1. Field of the Invention
The present invention relates to compositions for treating subterranean zones. The compositions include aqueous subterranean treatment fluids that contain water soluble polymers in a water-in-oil emulsion and associated methods.
2. Description of the Prior Art
Aqueous treatment fluids may be used in a variety of subterranean treatments. Such treatments include, but are not limited to, drilling operations, stimulation operations, and completion operations. As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid.
Viscous gelled fracturing fluids are commonly utilized in the hydraulic fracturing of subterranean zones penetrated by well bores to increase the production of hydrocarbons from the subterranean zones. That is, a viscous fracturing fluid is pumped through the well bore into a subterranean zone to be stimulated at a rate and pressure such that fractures are formed and extended into the subterranean zone. The fracturing fluid also carries particulate proppant material, e.g., graded sand, into the formed fractures. The proppant material is suspended in the viscous fracturing fluid so that the proppant material is deposited in the fractures when the viscous fracturing fluid is broken and recovered. The proppant material functions to prevent the fractures from closing whereby conductive channels are formed through which produced fluids can flow to the well bore.
An example of a stimulation operation utilizing an aqueous treatment fluid is hydraulic fracturing. In some instances, a fracturing treatment involves pumping a proppant-free, aqueous treatment fluid (known as a pad fluid) into a subterranean formation faster than the fluid can escape into the formation so that the pressure in the formation rises and the formation breaks, creating or enhancing one or more fractures. Enhancing a fracture includes enlarging a pre-existing fracture in the formation. Once the fracture is formed or enhanced, proppant particulates are generally placed into the fracture to form a proppant pack that may prevent the fracture from closing when the hydraulic pressure is released, forming conductive channels through which fluids may flow to the well bore.
During the pumping of the aqueous treatment fluid into the well bore, a considerable amount of energy may be lost due to friction between the aqueous treatment fluid in turbulent flow and the formation and/or tubular goods (e.g., pipes, coiled tubing, etc.) disposed within the well bore. As a result of these energy losses, additional horsepower may be necessary to achieve the desired treatment. To reduce these energy losses, friction reducing polymers have heretofore been included in aqueous treatment fluids. The friction reducing polymer should reduce the frictional losses due to friction between the aqueous treatment fluid in turbulent flow and the tubular goods and/or the formation.
In some instances, the friction reducing polymers that have been used previously are suspended in oil-external emulsions, wherein upon addition to the aqueous treatment fluid, the emulsion should invert releasing the friction reducing polymer into the fluid. One such friction reducing polymer is a copolymer of acrylic acid (in an amount of 30% by weight) and acrylamide (in an amount of 70% by weight). However, it is believed that the ionic nature of friction reducing polymers (such as the aforementioned copolymer) may cause the friction reducing polymers to function as flocculants. This may be undesirable, for example, in fracturing treatments in that the interaction of the friction reducing polymer with formation fines may result in the coagulation of formation fines into flocs. The resulting flocs may be undesirable, among other things, because the flocs may facilitate the formation of a stable emulsion in the formation possibly undesirably impacting subsequent production from the well bore.
One proposed solution to the aforementioned problems is disclosed in U.S. Pat. No. 7,004,254, which discloses aqueous treatment fluids that contain water, and a friction reducing copolymer that includes 60% to 90% by weight acrylamide and 10% to 20% by weight acrylic acid. The friction reducing copolymer is provided as a water-in-oil emulsion, where the polymer is present in the emulsion at 30% to 35% by weight of the emulsion. The treatment fluid is formed by combining the water-in-oil emulsion with additional water such that the polymer is present in the treatment fluid at from 0.025% to 0.1% by weight.
A particular problem with this approach is the high activity loading of the polymer in the water-in-oil emulsion polymer. Fracturing operations are often run at rates of 50 barrels per minute (BPM) or 35 gallons per second (GPS) and at times as fast as 100 BPM. These fracturing rates can require consumption rates of about 0.025 gallons of water-in-oil emulsion per second. Uniformity of mixing is strongly desired. However, even though good metering pumps are available, it is difficult to add such a low feed rate consistently and accurately and getting thorough mixing. The highly concentrated, compacted and intertwined polymer molecules often have an insufficient opportunity to disperse, separate and expand in the water, which results in less viscosity build and less of a friction reducing effect than would be expected for such a polymer.
Additionally, the relatively high polymer usage in subterranean treatment methods can result in significant formation damage. Further, when the treatment fluid is recycled above ground, the high levels of high molecular weight polymers in the fluid can lead to flocculation in above ground fluid recycle operations such as terminal upsets.
There is a need in the art to provide a water-in-oil friction reducing polymer that will allow for rapid make down and improved performance in treatment fluids for subterranean zones, overcoming the above-described problems.